1. Field of the Invention
The invention is related to the field of nuclear magnetic resonance ("NMR") well logging apparatus and methods. More specifically, the invention is related to methods for acquiring and processing NMR signals to determine particular properties of fluid-bearing earth formations penetrated by wellbores.
2. Description of the Related Art
NMR spin-echo measurements are known in the art for determining certain physical parameters of earth formations penetrated by wellbores. U.S. Pat. No. 5,712,566 issued to Taicher et al gives an explanation of the principles of NMR measurement as applied to determining the physical parameters as well as a description of apparatus used to make NMR measurements in wellbores drilled through earth formations.
Physical parameters of particular interest to wellbore operators are the fractional volume of pore spaces in the earth formations ("porosity") and the nature of the fluids contained in the pore spaces. In petroleum bearing earth formations, the pore spaces will typically contain some fractional volume of water and some fractional volume of hydrocarbons. Since hydrocarbons generally have different NMR relaxation properties than water, various NMR relaxometry techniques have been developed to qualitatively determine the nature of the fluids present in certain earth formations.
One method, for example, enables discriminating between gas and oil, and light oil and water. This method includes performing NMR spin-echo experiments using two different "wait times", TW. The wait time is the delay between individual Carr-Purcell-Meiboom-Gill ("CPMG") spin echo measurement sequences. See S. Meiboom et al, Rev. of Sci. Instr. v. 29, p. 6881 (1958). Another technique, described in U.S. Pat. No. 5,498,960 issued to Vinegar et al, uses two different interecho spacing times, TE, for CPMG sequences measured in a gradient magnetic field. The interecho spacing is the time between rephasing radio frequency (RF) energy pulses applied to the logging instrument's antenna to "rephase" precessing nuclei which are the subject of the NMR experiment. The rephasing RF pulses result in the "spin echoes" whose amplitude is measured. Gas, oil and water generally have different self-diffusivities, and these differences will be reflected in differences in the apparent transverse relaxation time T.sub.2 calculated for an earth formation between CPMG sequences measured using different values of TE. The technique described in the Vinegar et al '960 patent for discriminating types of fluids in pore spaces of earth formations typically uses two values of TE.
Another physical property of particular interest is the viscosity of any oil which may be present in the pore spaces of the earth formation. In a paper by R. Akkurt et al entitled, "NMR Logging and Natural Gas Reservoirs", 36th annual symposium, Society of Professional Well Log Analysts (1995), a relationship is described between an intrinsic transverse relaxation time, T.sub.2int, for oil with respect to its viscosity, .eta.: ##EQU1## where t.sub.k represents the absolute (Kelvin) temperature of the oil and x represents an empirical fit factor, typically about equal to unity. A difficulty in determining oil viscosity using this relationship is that it requires determining the intrinsic transverse relaxation time. For NMR logging instruments which use a gradient static magnetic field, such as the one described in the Taicher et al '566 patent, the transverse relaxation time calculated from spin-echo amplitude measurements is affected by the self-diffusion effect. The apparent T.sub.2 calculated from the spin echo amplitudes is related to T.sub.2int in the following manner: ##EQU2## where the self-diffusion effect T.sub.2D can be determined by the expression: ##EQU3## TE is generally selected by the system operator and has a known value. .gamma., the gyromagnetic ratio, is unique for each chemical isotope. The magnitude of the static magnetic field in which the CPMG sequences are actually measured is therefore controlled by selection of the frequency of the RF pulses. Since the spatial distribution of the static magnetic field amplitude and gradient magnitude are known, the gradient of the static magnetic field in the NMR excitation volume will also be known for any selected RF excitation frequency. The actual magnetic field gradient within the pore spaces of the earth formation may not be known, however, since the field gradients internal to the pore spaces depend on differences in magnetic susceptibility between the formation solids ("matrix") and the fluid in the pore spaces, as well as the amplitude of the static magnetic field. See for example, U.S. Pat. No. 5,698,979 issued to Taicher et al. Therefore the relationship in equation (3) is typically not useful to correct T.sub.2 values for diffusion effect, because the gradient inside the pore spaces is not readily determinable.
As can be inferred from equations (2) and (3), the difference between the apparent T.sub.2 from the CPMG sequence measured at one TE and the apparent T.sub.2 determined from the CPMG sequence measured at the other TE could provide information related to the diffusion effect, and thereby the viscosity of any oil which may be present in the pore spaces of the earth formations. It has proven difficult to quantify the difference in apparent T.sub.2 using acquisition and processing techniques known in the art, however, because the spin echo amplitude signals acquired using both TE values will typically have some partial contribution from any water present in the pore spaces. The spin echo signals are also typically affected by some amount of noise.